Integrated hydrogen production and hydrocarbon extraction

ABSTRACT

Reformer and method for producing hydrogen and steam where steam is used for steam-assisted extraction of heavy hydrocarbons. Steam is injected into a hydrocarbon-containing reservoir. Hydrocarbons are extracted from the reservoir along with produced water. Hydrogen is produced in a catalytic steam hydrocarbon reformer. Combustion product gas from the reformer is used to generate wet steam in a once-through steam generator from produced water recycled from the reservoir. The wet steam is used for the steam-assisted extraction of heavy hydrocarbons. The reformer has a heat exchanger section including a first heat exchanger and a second heat exchanger downstream of the first heat exchanger. The second heat exchanger is suitable for processing the produced water by once-through steam generation and is suitable for mechanical cleaning. The reformer also has a first exhaust downstream of the second heat exchanger and a closeable second exhaust downstream of the first heat exchanger.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application and claims the benefit ofpriority under 35 USC 120 of U.S. application Ser. No. 12/642,249, filedDec. 18, 2009, the contents of which are hereby incorporated byreference.

BACKGROUND

Oil sand deposits, located in many regions of the world, comprisemixtures of sand, water, clay, minerals, and crude bitumen that can beextracted and processed for fuel. The oil sands of Alberta, Canada,contain some of the largest deposits of hydrocarbons in the world.

Bitumen is classified as an “extra heavy oil,” referring to its gravityas measure in degrees on the American Petroleum Institute (API) scale.Bitumen has an API gravity of about 10° or less. The bitumen mined fromthe Athabasca oil sands of Alberta has an API gravity of about 8°.“Heavy oil” has an API gravity in the range of about 22.3° to about 10°.Heavy oil or bitumen extracted from oil sand is processed or upgraded toproduce light synthetic crude oil having an API gravity of about 31° toabout 33°. The terms heavy oil and bitumen are used interchangeablyherein since they may be extracted using the same processes.

Bitumen can be recovered from the oil sands by various methods, the mostcommon of which include surface or strip mining and in-situ bitumenrecovery methods, including thermal in-situ recovery methods. Theoperations for recovery and extraction of bitumen are highly waterintensive, thus facilities must generally draw from a dedicated watersource, such as a nearby river or lake. The waste, including waterwaste, produced during these operations, is disposed of in tailingsponds, sludge lagoons, disposal wells and the like. There is a demand inthe industry to reduce water consumption and waste associated withbitumen recovery and extraction processes and to minimize the overallland footprint and environmental impact of these operations.

There may be environmental restrictions placed on heavy oil/bitumenextraction operations that utilize fresh water. These restrictionsrelate to the amount of fresh water that can be removed from a source inthe environment of the operation, such as from a lake, river, or freshwater aquifer. In some instances, the amount of fresh water that can bewithdrawn may be a rate-limiting factor in the overall production of theoperation. In such an instance, efficient re-use of water can directlyimpact the production of an operation.

Extracted bitumen may be pumped via pipeline to an upgrader on site orto a refinery for cleaning, treatment and upgrading. Upgrading ofbitumen or heavy oil to a light synthetic crude oil is generallyaccomplished via carbon rejection (i.e. coking) or hydrogen addition.The latter process is typically a two-stage process involvinghydrocracking to break down the large hydrocarbon molecules andhydrotreating to stabilize the hydrocarbon compounds and removeimpurities. The upgraded synthetic crude oil can be sold to refineries,petrochemical manufacturers or other consumers.

Bitumen extraction operations require expensive and elaborate processingfacilities and an abundance of water, as well as energy for heat andsteam generation. On average, one and a half to two tons of oil sandmust be processed to produce one 159-liter barrel of synthetic crude oilfrom bitumen. Large quantities of oil sand must be mined and processedeach day in order to supply the high demand for synthetic crude oil.

In-situ oil recovery methods, such as thermal in-situ recovery methods,are applied when the bitumen is buried deep within a reservoir andcannot be mined economically due to the depth of the overburden. In-situproduction methods may recover between about 25 and 75 percent of thebitumen initially present in a reservoir. In general the focus of anin-situ recovery process is to reduce the viscosity of the bitumen orheavy oil to enable it to flow and be produced from a well.

Thermal in-situ recovery processes use heat, typically provided bysteam, to reduce the viscosity of the bitumen in a reservoir and therebyrender it more flowable. Examples of thermal in-situ recovery processesinclude but are not limited to steam-assisted gravity drainage (SAGD),cyclic steam stimulation (CSS), and various derivatives thereof, such assolvent-assisted SAGD (SA-SAGD), steam and gas push (SAGP), combinedvapor and steam extraction (SAVEX), expanding solvent SAGD (ES-SAGD),constant steam drainage (CSD), and liquid addition to steam enhancingrecovery (LASER), as well as water flooding and steam floodingprocesses.

In typical gravity-driven thermal in-situ oil recovery processes, twohorizontal wells are drilled into the reservoir. A lower horizontalwell, ideally located near the bottom of the reservoir, serves as aproduction well and a horizontal well located above the production wellserves as an injection well. Dry or wet steam is injected into theinjection well from the surface to heat the bitumen trapped in thereservoir and lower its viscosity. An enormous quantity of steam must begenerated for this process and the water used for steam generation inconventional processes must meet boiler feed water specifications. Asthe viscosity of the bitumen is lowered, it flows into the productionwell, along with condensed steam, and these liquids are pumped to thesurface. A hydrocarbon solvent or other agent may optionally be injectedto assist the process.

The hot production fluids, typically comprising about 70% produced waterand about 30% bitumen and produced gases, are recovered to the surfacevia the production well and are separated into their individualcomponents on site. Production fluids from the wellhead are sent to aflow splitter to separate the bitumen, produced water and optionallyproduced gas into individual streams. A diluent or condensate is addedto the bitumen stream to facilitate the removal of residual water fromthe oil. The diluted bitumen (“dilbit”) may be further treated or storedon site before being transported to an upgrader or pipelined to arefinery. The produced gas stream may be used to provide fuel for thesteam generators.

The produced water (PW) stream is typically sent to water treatmentfacilities to make boiler feed water of suitable quality for steamgeneration. In this process, the PW stream is first deoiled and is thensent for softening treatment. The conventional approach used to treat orsoften the produced water to meet boiler feed water specifications is atwo-step process involving primary hardness removal followed bysecondary hardness removal to polish the water.

This conventional configuration results in numerous waste streams thatmust be handled and the residual waste is ultimately sent to a disposalwell or costly sludge lagoon on site.

There is an economic incentive for improving efficiencies in the bitumenand heavy oil industry in general and, in particular, for reducingcapital and operating costs, water consumption, land footprint and theenvironmental impact associated with bitumen recovery operations. Whileattempts to reuse and recycle water for improved efficiency within anin-situ recovery operation, or within a mining operation, have beenmade, advantages to be achieved by integrating an in-situ operation withhydrogen production have not been fully appreciated.

There is a need to generate steam and hydrogen for the steam-assistedextraction of the heavy hydrocarbons from the hydrocarbon-containingreservoir and upgrading of the extracted heavy hydrocarbons.

It is desirable to provide new and improved methods and systems forimproving efficiencies in water and energy consumption and also toreduce environmental impact of water consumption and waste disposalassociated with bitumen mining and in-situ recovery operations, andreduce capital and operational costs. The reduction of the carbonintensity of bitumen production through efficiency gains or carbondioxide capture is important for environmental reasons and formaintaining the marketability of bitumen-derived fuels.

There is a need for technologies which capture and re-use water so as tominimize input of fresh water. Industry desires to conserve/minimize theamount of water used for steam injection at hydrocarbon extractionsites.

Sites for heavy hydrocarbon extraction and upgrading of the heavyhydrocarbons are generally remote and co-production of electricity foruse in the production facility is sometimes desired as well.

Industry desires improved energy efficiency for the production of steam,hydrogen, and/or electricity.

Industry desires the ability to adjust one or more of the various ratiosof steam:hydrogen, steam:electricity produced at a site.

Industry desires uninterrupted supply of hydrogen for upgrading heavyhydrocarbons.

The present invention aims to satisfy one or more of these and otherdesires of industry.

BRIEF SUMMARY

Generally, the present invention relates to the bitumen and heavy oilindustry. The present invention relates to a hydrocarbon processingmethod and apparatus therefor. More specifically the present inventionrelates to a method and related reformer for producing hydrogen andsteam where the steam is injected into a hydrocarbon-containingreservoir to aid in hydrocarbon extraction.

The method comprises injecting a steam-containing stream through aninjection well into a hydrocarbon-containing reservoir; extractinghydrocarbons from the hydrocarbon-containing reservoir and withdrawingthe hydrocarbons and recycle water through a production well, therecycle water formed from a portion of the steam-containing stream;introducing a reformer feed gas mixture into a plurality ofcatalyst-containing reformer tubes of a catalytic steam reformer andreacting the reformer feed gas mixture in a reforming reaction underreaction conditions effective to form a process gas comprising hydrogen;combusting a fuel with an oxidant gas in a combustion section of thereformer external to the plurality of catalyst-containing tubes underconditions effective to combust the fuel to form a combustion productgas and generate heat to supply energy for the reforming reaction;heating a first stream comprising the recycle water and optionallyinjection make-up water by indirect heat transfer with the combustionproduct gas thereby producing steam for the steam-containing stream fromthe first stream, the steam produced at a first pressure between 1 MPa(absolute) to 10 MPa (absolute) or between 2 MPa (absolute) to 6 MPa(absolute) with a first steam quality less than 100% on a mass flow ratebasis; conditioning process make-up water in a boiler feed waterpreparation system to produce boiler feed water from the process make-upwater; and heating the boiler feed water by indirect heat transfer withat least one of the process gas and the combustion product gas therebyforming process steam, wherein the reformer feed gas mixture comprisesthe process steam.

In one or more embodiments, the boiler feed water does not compriserecycle water.

In one or more embodiments, less than 10% on a mass flow rate basis ofthe steam in the steam-containing stream is from the boiler feed water.

In one or more embodiments, the steam-containing stream is not formedfrom the boiler feed water.

The process steam may be separated from the boiler feed water in a steamdrum.

The first stream may further comprise injection make-up water.

The method may further comprise heating a second stream comprising atleast one of injection make-up water and recycle water by indirect heattransfer with the process gas followed by heating the second stream byindirect heat transfer with the combustion product gas mixture therebyproducing additional steam for the steam-containing stream from thesecond stream, the additional steam produced at the first pressure withthe first steam quality or a second pressure between 1 MPa (absolute) to10 MPa (absolute) or between 2 MPa (absolute) to 6 MPa (absolute) with asecond steam quality less than 100% on a mass flow rate basis.

The first steam quality may be between 50% and 85% and the second steamquality may be between 50% and 85%.

The process gas may be shifted in one or more shift reactors prior toindirect heat exchange with the second stream.

The method may further comprise removing CO₂ from the process gaswherein the steam-containing stream comprises the removed CO₂.

The method may further comprise condensing water in the process gas toform a condensate and a water-depleted process gas; separating thecondensate from the water-depleted process gas wherein the boiler feedwater comprises the condensate; and separating the water-depletedprocess gas into a hydrogen product gas and a residual gas wherein thefuel comprises the residual gas.

The method may further comprise withdrawing hydrocarbon gases from theproduction well wherein the reformer feed gas mixture comprises thehydrocarbon gases and/or the fuel comprises the hydrocarbon gases.

The method may further comprise operating a gas turbine power generatorto form electrical power and a gas turbine exhaust wherein the oxidantgas comprises the gas turbine exhaust.

The method may further comprise heating a third stream comprising atleast one of the injection make-up water and the recycle water in a heatrecovery steam generator thereby producing even more additional steamfor the steam-containing stream from the third stream, the even moreadditional steam produced at a third pressure between 1 MPa (absolute)to 10 MPa (absolute) or between 2 MPa (absolute) to 6 MPa (absolute) anda third steam quality less than 100% on a mass flow rate basis, whereina combustion oxidant for the heat recovery steam generator comprises thegas turbine exhaust. The third steam quality may be between 50% and 85%.

The method may further comprise exhausting the combustion product gasfrom the reformer at a location upstream of a heat exchanger thatprovides the indirect heat transfer between the first stream and thecombustion product gas, thereby discontinuing heating of the firststream; and cleaning the heat exchanger while continuing to form theprocess gas comprising hydrogen.

The reformer comprises a combustion section for performing a combustionreaction; a plurality of catalyst-containing tubes for performing areforming reaction, the plurality of catalyst-containing tubes locatedwithin the combustion section; and a heat exchanger section downstreamof the combustion section for receiving combustion product gases fromthe combustion reaction. The heat exchanger section comprises a firstheat exchanger for transferring heat from the combustion product gasesto a reformer feed gas mixture; a second heat exchanger downstream ofthe first heat exchanger with respect to the flow of the combustionproduct gases for transferring heat from the combustion product gases torecycle water to produce a steam-containing stream from the recyclewater, wherein the second heat exchanger is suitable for mechanicalcleaning; and a first exhaust downstream of the second heat exchangerwith respect to the flow of the combustion product gases for exhaustingthe combustion product gases from the heat exchanger section.

The heat exchanger section of the reformer may further comprise aclosable second exhaust downstream of the first heat exchanger withrespect to the flow of the combustion product gases and upstream of thesecond heat exchanger with respect to the flow of the combustion gases.

BRIEF DESCRIPTION OF SEVERAL VIEWS OF THE DRAWINGS

FIG. 1 is a process flow diagram of an integrated system for producinghydrogen and steam.

FIG. 2 is a schematic of a reformer.

DETAILED DESCRIPTION

The articles “a” and “an” as used herein mean one or more when appliedto any feature in embodiments of the present invention described in thespecification and claims. The use of “a” and “an” does not limit themeaning to a single feature unless such a limit is specifically stated.The article “the” preceding singular or plural nouns or noun phrasesdenotes a particular specified feature or particular specified featuresand may have a singular or plural connotation depending upon the contextin which it is used. The adjective “any” means one, some, or allindiscriminately of whatever quantity.

The phrase “at least a portion” means “a portion or all.”

As used herein, “plurality” means at least two.

For the purposes of simplicity and clarity, detailed descriptions ofwell-known devices, circuits, and methods are omitted so as not toobscure the description of the present invention with unnecessarydetail.

Illustrative embodiments of the invention are described with referenceto the FIG. 1. While the invention is susceptible to variousmodifications and alternative forms, specific embodiments thereof havebeen shown by way of example in the drawings and are herein described indetail. It should be understood, however that the description herein ofspecific embodiments is not intended to limit the invention to theparticular forms disclosed, but on the contrary, the invention is tocover all modifications, equivalents, and alternatives falling withinthe scope of the invention as defined by the appended claims.

It will of course be appreciated that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming, but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The method comprises injecting a steam-containing stream 550 through aninjection well 700 into a hydrocarbon-containing reservoir 703 andextracting hydrocarbons 710 from the hydrocarbon-containing reservoir703. The extracted hydrocarbons may be heavy oil or bitumen, for examplefrom oil-sands reservoirs. The hydrocarbons 710 may be conveyed to aprocessing facility, for example an upgrader, for upgrading thehydrocarbons by reaction with hydrogen.

The steam-containing steam is generally a wet steam, meaning that itcontains liquid water in addition to steam. As is known in the art, thesteam-containing stream may also comprise carbon dioxide and/or a heavyhydrocarbon solvent. The addition of a small amount, for example between0.1 and 15 volume % of heavy hydrocarbon solvent will provide furtherheavy oil or bitumen mobilization, as the heavy hydrocarbon solventdissolves into the bitumen, thereby reducing the viscosity of the heavyoil or bitumen such that it flows to a production well. The solvent willalso serve to dilute the produced heavy oil or bitumen to help realizethe fluid property specifications required for transport by pipeline.Preferably, the solvent is from 1 to 10 volume %, and most preferablybetween 3 and 8 volume %.

Hydrocarbons 710 and recycle water 500 are withdrawn through aproduction well 705. Recycle water 500 is formed from a portion of thesteam-containing stream 550; a portion of the water and condensed steamfrom the steam-containing stream 550 is reclaimed as recycle water 500and another portion of the water and condensed steam is lost to theenvironment. As defined herein, recycle water is any water that isremoved from the production well.

Injecting steam into a hydrocarbon-containing reservoir may be part of asteam flooding operation, steam assisted gravity drainage (SAGD) processor other hydrocarbon extraction process where steam injection is used.Steam flooding is discussed in numerous U.S. Patents including U.S. Pat.No. 4,133,384. Steam assisted gravity drainage (SAGD) is discussed innumerous U.S. Patents including U.S. Pat. No. 6,988,549 and U.S. Pat.No. 4,344,485. Solvent-assisted vapor extraction with steam (SAVES) isdiscussed in U.S. Pat. No. 7,464,756. Injecting steam intohydrocarbon-containing reservoirs for hydrocarbon extraction iswell-known. Procedures, techniques and equipment for injecting steaminto hydrocarbon-containing reservoirs are known and available.

The method also comprises introducing a reformer feed gas mixture 10into a plurality of catalyst-containing reformer tubes 101 of acatalytic steam reformer 100 and reacting the reformer feed gas mixture10 in a reforming reaction under reaction conditions effective to form aprocess gas 12 comprising hydrogen. The reaction conditions effective toform the process gas comprising hydrogen include a temperature rangingfrom 700° C. to 1000° C. and a pressure ranging from 1 to 50atmospheres. Preferred operating conditions for reforming are known inthe art.

Catalytic steam reforming, also called steam methane reforming (SMR) orsteam reforming, is defined as any process used to convert reformerfeedstock to synthesis gas by reaction of a hydrocarbon and steam over acatalyst. The term “synthesis gas,” commonly called syngas, is usedherein to mean any mixture comprising hydrogen and carbon monoxide. Thereforming reaction is an endothermic reaction and may be describedgenerally as

${{C_{n}H_{m}} + {n\; H_{2}O}}->{{n\;{CO}} + {\left( {\frac{m}{2} + n} \right){H_{2}.}}}$Hydrogen is generated when synthesis gas is generated.

A catalytic steam reformer is a reactor for performing the reformingreaction.

The process gas 12 is often called a reformate. As used herein, areformate is any mixture comprising hydrogen and carbon monoxide formedfrom the reforming reaction of a hydrocarbon and steam.

The reformer feed gas mixture comprises methane and steam. The reformerfeed gas mixture may also comprise other hydrocarbons, for example, C2to C6 hydrocarbons and/or naphtha.

The reformer feed gas mixture may have been processed in a prereformer(not shown) prior to introducing the reformer feed gas mixture into theplurality of catalyst-containing reformer tubes. A prereformer isdefined herein as any unfired vessel that converts hydrocarbon feedstockby reaction with steam over a catalyst with or without heating. Aprereformer may be an adiabatic fixed bed reactor. A prereformer may bea tubular reactor. A prereformer generally employs a different type ofcatalyst than a primary reformer, for example a high activity, highnickel content catalyst. Suitable catalysts for prereformers are knownin the art. Temperatures in a prereformer may be in the range of about400° C. to about 600° C. Heat to a prereformer may be provided fromexhaust gases from a reformer or other source, but is characterized bythe lack of direct heating by a combustion flame. A prereformer and areformer may be physically connected. The prereformer may be a so-calledconvective prereformer where the prereformer is heated by combustionproduct gases from the reformer.

The system may also include a convective heat transfer reformer (notshown) as described in U.S. Pat. No. 5,264,202 and/or an oxygensecondary reformer.

As shown in the FIG. 1, the reformer feed gas mixture 10 may be formedby mixing a hydrocarbon feedstock 1 comprising methane with steam 200.The hydrocarbon feedstock may comprise hydrocarbon gases 720 withdrawnfrom the production well 705. The hydrocarbon feedstock may be heated byheat exchange with the process gas 12 to form the hydrocarbon feedstock2 which has been heated. Sulfur may be removed from the hydrocarbonfeedstock 2 in desulphurization unit 300 to form hydrocarbon feedstock 3which has been desulphurized.

Reformer furnaces with a plurality of catalyst-containing reformertubes, i.e. tubular reformers, are well known in the art. Suitablematerials and methods of construction are known. Catalyst in thecatalyst-containing reformer tubes may be any suitable catalyst known inthe art, for example, a supported catalyst comprising nickel.

The method further comprises combusting a fuel 30, 32 with an oxidantgas 103 in a combustion section 110 of the reformer 100 external to theplurality of catalyst-containing tubes 101 under conditions effective tocombust the fuel 30, 32 to form a combustion product gas 130 andgenerate heat to supply energy for the reforming reaction.

Fuel introduced into the combustion section of the reformer may be anyfuel suitable for providing heat by combustion in the reformer. The fuelmay include pressure swing adsorber residual gas, natural gas,hydrocarbon gases 720 from the reservoir 703, purified methane, propaneand the like. Pressure swing adsorber residual gas is any effluentstream from a pressure swing adsorber excluding the hydrogen productstream. Since the articles “a” and “an” as used herein mean one or morewhen applied to any feature in the specification and the claims, one ormore fuels may be introduced into the combustion section of thereformer. It is often the case that multiple fuels are used. A pressureswing adsorber residual gas may be the primary fuel and a supplementalfuel, such as natural gas, added as needed to boost the combustionenergy provided for the reforming reaction. The added supplemental fuelis sometimes referred to as “trim fuel.”

The combustion section of the reformer is a section wherein combustionoccurs. Generally a flame is visible, however flameless combustion mayalso be used.

The oxidant gas 103 is a gas comprising oxygen. As used herein a “gas”may be a single gas species or a gaseous mixture. The oxidant gas may beair having an oxygen concentration of about 21 volume %. The oxidant gasmay be oxygen-enriched air having an oxygen concentration of greaterthan 21 volume % to 70 volume %. The oxidant gas may be oxygen-depletedair having an oxygen concentration of 13 volume % to less than 21 volume% or 15 volume % to less than 21 volume %, for example exhaust from agas turbine. At least a portion of the oxidant gas may be introducedinto the reformer combustion section through lances. The oxidant gas maybe preheated having a temperature of 100 to 600° C. The oxidant gas maybe preheated by heat exchange (not shown) between a combustion productgas mixture 130 and/or process gas 12.

At least a portion of the fuel 10 may be premixed with oxidant gas 103prior to introducing the fuel into the combustion section 110. At leasta portion of the fuel may be introduced into the combustion sectionthrough fuel lances. To ensure substantially complete combustion of thefuel, a molar ratio of oxygen to fuel is generally provided with astoichiometry so as to provide about 5 to 10 volume % excess oxygen.Consequently, oxygen is present in the combustion product gas mixture130.

Fuel and oxidant may be introduced through burners. Burners for use withreformers are available commercially.

Conditions effective to combust the fuel to form a combustion productgas include a furnace temperature in the range of 700° C. to 2500° C.and a pressure in the range of 0.9 to 1.1 atm. In air, the ignitiontemperature of CH₄ is about 700° C. The furnace temperature is a furnacegas temperature in the combustion section of the reformer outside of theflame envelope and may be determined by a suction pyrometer. Suitableconditions include a furnace temperature in the range of 1500° C. to2500° C. or 1700° C. to 2300° C. and a pressure in the range of 0.9 to1.1 atm. Preferred combustion conditions in reformers are known in theart.

When the fuel and oxygen are combusted, heat is generated and acombustion product gas 130 is formed. Heat from the combustion processis transferred to the plurality of catalyst-containing reformer tubes101 thereby supplying energy for the endothermic reforming reaction. Thecombustion product gas is any gas mixture resulting from at leastpartial combustion of the fuel and the oxygen and comprises CO₂ and H₂O.The combustion product gas mixture may comprise H₂O, CO₂, N₂, O₂, andgenerally lesser amounts of CO and unburned hydrocarbons.

The combustion product gas mixture may also comprise NOx or otherpollutant gases. NOx reduction techniques known in the art of industrialcombustion may be used, for example flue gas recirculation, fuelstaging, oxygen staging, selective catalytic or non-catalytic reductionwith ammonia, etc.

The combustion product gas may be passed from the combustion section 110to a heat exchanger section 120 of the reformer where heat may betransferred from the combustion product gas to other streams therebyincreasing the efficiency of the overall process. The heat exchangersection 120 is often called the convection section of the reformer. Thecombustion section of the reformer is also called the radiant section ofthe reformer due to the radiant heat transfer from the combustion flamesto the reformer tubes. There is essentially no radiant heat transferfrom the combustion flames in the combustion section to the heattransfer tubes in the heat exchanger section of the reformer.

The method further comprises heating a first stream 503 comprising therecycle water 500 and optionally injection make-up water 501 by indirectheat transfer with the combustion product gas 130 thereby producingsteam for the steam-containing stream 550 from the first stream 503.Prior to heating the recycle water 500, the recycle water may be cleanedup, for example filtered, but not nearly so much as typical boiler feedwater. The steam produced at a first pressure between 1 MPa (absolute)to 10 MPa (absolute) or between 2 MPa (absolute) to 6 MPa (absolute)with a first steam quality less than 100% on a mass flow rate basis. Thefirst pressure may be selected based upon the reservoir properties anddistance between the steam generation site and the reservoir. The firststeam quality may be between 50% and 85% on a mass flow rate basis. Amixture of steam and water is often called wet steam. For the purposesof this disclosure, steam quality in the range of 50% to 90% is asmeasured by the method and device disclosed in U.S. Pat. No. 5,214,956.In carrying out the method, steam quality may be measured by any knownmeans with steam quality correlated to the measurements obtained by thedevice described in U.S. Pat. No. 5,214,956. Steam quality in the rangegreater than 90%, is as measured by a throttling calorimeter, forexample, see Marks' Mechanical Engineer's Handbook, Sixth Edition, T.Baumeister, Ed., p. 16-27, McGraw-Hill Book Co., 1958. Measuring thesteam quality is not required for carrying out the method.

The recycle water 500 and the heavy oil or bitumen are separated and therecycle water contains higher concentrations of suspended and/ordissolved solids and other contaminants than typical boiler feed water.

Generally, not all of the steam/water injected at the injection wellwill be recovered at the production well 705, so that injection make-upwater 501 is added to the recycle water 500. As shown in the FIG. 1,recycle water 500 and optional injection make-up water 501 may be pumpedto heat exchangers 144 and 146 in the heat exchanger section 120 of thereformer 100.

With reference to the FIG. 1, the recycle water 500 is heated byindirect heat transfer with the combustion product gas 130 in heatexchangers 144 and 146. Heat exchangers 144 and 146 are operated asonce-through steam generators. Once-through steam generation (OTSG)system, also called a once-through heat recovery steam generation(OTHRSG) system are known in the art.

Once-through steam generation systems are used for water which containshigh concentrations of suspended and/or dissolved solids. In the priorart, heat is provided in the once-through steam generators by firing agas or liquid fuel with air or a gas turbine exhaust as the oxidant.

In the present method, heat for the once-through steam generation isprovided by the combustion product gas 130 from the combustion section110 of the reformer. Heat for the once-through steam generation may beprovided solely by the heat contained in the combustion product gas. Inanother alternative, the reformer may be operated fuel-rich andadditional oxidant added to combustion product gas for additionalcombustion and heat. In yet another alternative, the reformer may beoperated fuel-lean and additional fuel added to the combustion productgas for additional combustion and heat. In yet another alternative,additional fuel and oxidant may be added to the combustion product gasand combusted in the heat exchanger section. In these alternatives, theheat provided by additional combustion in the heat exchanger section isgenerally less than 10% of the heat provided in the combustion section.

U.S. Pat. No. 4,759,314 provides some guiding principles for control ofonce-through steam generators.

As shown in the FIG. 1, the first stream 503 comprising recycle water500 may be heated by heat exchange with the combustion product gas 130in heat exchanger 146, combined with another stream and then furtherheated by the combustion product gas 130 to produce steam in heatexchanger 144. The wet steam produced in heat exchanger 144 may thenpassed to the injection well 700 as steam-containing stream 550.

As shown in the FIG. 1, the reformer feed gas mixture 10 may also beheated by the combustion product gas 130 in heat exchanger 148. The heatexchanger 148 for heating the reformer feed gas mixture is preferablyupstream of the heat exchangers 144, 146 for heating the first stream503. Under normal operation, the combustion product gas heats thereformer feed gas mixture 10 and the first stream 503 and is exhaustedfrom the heat exchanger section of the reformer through an exhaust orstack downstream of the heat exchangers 144, 146.

A secondary combustion product gas removal system 132 may be locateddownstream of the heat exchanger 148 for heating the reformer feed gasmixture and upstream of the heat exchangers 144, 146 for heating stream503. Since the first stream 503 contains suspended and/or dissolvedsolids, the heat exchangers 144, 146 will require maintenance. When theheat exchangers 144 and 146 require cleaning and/or other maintenance,the combustion product gas 130 is exhausted through the secondarycombustion product gas removal system 132. The heating of the firststream 503 is discontinued and the heat exchangers are cleaned orotherwise maintained. This will provide the benefit that the reformerfeed gas mixture 10 is still heated as required for the hydrogenproduction process.

Accordingly, the present invention also relates to a reformer as shownin FIG. 2. The reformer 100 comprises a combustion section 110 forperforming a combustion reaction. Fuel 32 and oxidant gas 103 areintroduced into the combustion section 110 through a plurality ofburners. Burners for reformers are available commercially. The burnersmay be fuel-staged and or oxidant-staged burners. One skilled in the artcan readily select suitable burners. The reformer also comprises aplurality of catalyst-containing tubes 101 for performing the reformingreaction. The plurality of catalyst-containing tubes 101 are locatedwithin the combustion section 110 of the reformer 100. Process gas 12comprising hydrogen is removed from the catalyst-containing tubes 101.The reformer also comprises a heat exchanger section 120 downstream ofthe combustion section 110 for receiving combustion product gases fromthe combustion reaction.

The heat exchanger section comprises a first heat exchanger 148 fortransferring heat from the combustion product gases to a reformer feedgas mixture 10. The heat exchanger section also comprises a second heatexchanger 144, 146 downstream of the first heat exchanger with respectto the flow of the combustion product gases. The second heat exchangeris for transferring heat from the combustion product gases to one ormore streams comprising recycle water 502 to produce steam-containingstream 550 from recycle water. The second heat exchanger is constructedto be suitable for mechanical cleaning. Mechanical cleaning of such heatexchangers is typically called “pigging.”

The heat exchanger section further comprises a first exhaust 134 whichis located downstream of the second heat exchanger 144, 146, where“downstream” is with respect to the flow of the combustion productgases. The first exhaust is suitable for exhausting the combustionproduct gases from the heat exchanger section.

The heat exchanger section may further comprise a closable secondexhaust 132 which is located downstream of the first heat exchanger 148,where downstream is with respect to the flow of the combustion productgases. The closable second exhaust 132 is located upstream of the secondheat exchanger 144, 146, where upstream is with respect to the flow ofthe combustion product gases. Under normal operating conditions,closable second exhaust 132 is closed and the combustion product gasesexit the heat exchanger section through the first exhaust 134.

When the second heat exchanger 144, 146 requires cleaning and/or othermaintenance, closable second exhaust 132 is opened and the combustionproduct gases are diverted and inhibited from passing in heat transferrelationship with second heat exchanger 144, 146. Closable secondexhaust 132 is constructed to be suitable for diverting the combustionproduct gases. Having a closable second exhaust 132 provides the benefitof allowing continued production of hydrogen when the second heatexchanger 144, 146 is cleaned and/or maintained. It is not importantwhether the first exhaust 134 is closable or not.

The method comprises conditioning process make-up water 170 in a boilerfeed water preparation system 410 to produce boiler feed water 173 fromthe process make-up water 170. The boiler feed water 173 may alsocomprise condensate 171 from the process gas 14. Boiler feed water isgenerally conditioned to make the water suitable for use in packagedboilers. Boiler feed water is generally conditioned for removal ofsuspended solids, removal of hardness by chemical treatment, removal ofhardness by cation exchange, removal of dissolved solids bydemineralization, removal of gases by deaeration, and pH treatment.Boiler feed water conditioning is known in the art and is discussed inMarks' Mechanical Engineers' Handbook, Sixth Edition, McGraw-Hill BookCompany, 1958, pp. 9-46 through 9-52.

As used herein, “conditioning” water means one or more of removal ofsuspended solids, removal of hardness, removal of dissolved solids,removal of gases and pH treatment. Conditioning may include all ofremoval of suspended solids, removal of hardness, removal of dissolvedsolids and removal of gases.

The method comprises heating the boiler feed water 173, 175 by indirectheat transfer with at least one of the process gas 12 and the combustionproduct gas 130 thereby forming process steam 200. In the FIG. 1, theboiler feed water 173 is heated by the process gas 12 in heat exchanger303 and the boiler feed water 174 which has been heated is passed to anoptional steam drum 440. Water and steam are separated in steam drums.The process steam 200 is separated from the boiler feed water 175 insteam drum 440. The steam from the steam drum is mixed with ahydrocarbon feedstock 3 to form the reformer feed gas mixture 10. Thereformer feed gas mixture 10 comprises the process steam 200. In theFIG. 1, water 175 from the steam drum 440 is heated by the process gas12 in heat exchanger 301 where a two-phase mixture of steam and water177 is then returned to the steam drum. Although not shown in the FIG.1, the water from the steam drum may be additionally or alternativelyheated by the combustion product gases 130.

In one or more embodiments, steam for the process steam 200 is formedseparately from the steam for the steam-containing stream 550. In one ormore embodiments, the boiler feed water 173, 175 does not compriserecycle water 500. Since the boiler feed water is used to form steam forthe reformer feed gas mixture 10 and the boiler feed water does notcomprise recycle water, the reformer feed gas mixture will not comprisesteam formed from recycle water 500.

In one or more embodiments, steam for the steam-containing stream 550 isnot formed from the boiler feed water 173, 175. However, in otherembodiments, it is possible that a small amount, less than 10% on a massflow rate basis of the steam in the steam-containing 550 may haveoriginated from the boiler feed water 173, 175.

As shown in the FIG. 1, the method may further comprise heating a secondstream 502 comprising at least one of the injection make-up water 501and the recycle water 500. The second stream 502 is heated by indirectheat transfer with the process gas 14 in heat exchanger 314. The secondstream 502 is further heated by indirect heat transfer with thecombustion product gas mixture 130 in heat exchanger 144 therebyproducing additional steam for the steam-containing stream 550 from thesecond stream 502. With reference to the FIG. 1, the first stream 503and the second stream 502 may be combined into stream 505 and heatedtogether in heat exchanger 144 by indirect heat transfer with thecombustion product gas mixture 130. As discussed above, heat exchanger144 is operated as a once-through steam generator and produces wetsteam. The additional steam is produced at the first pressure with thefirst steam quality or a second pressure between 1 MPa (absolute) to 10MPa (absolute) or between 2 MPa (absolute) to 6 MPa (absolute) with asecond steam quality less than 100% on a mass flow rate basis. Thesecond pressure may be selected based upon the reservoir properties anddistance between the steam generation site and the reservoir. The secondsteam quality is different than the first steam quality and may bebetween 50% and 85% on a mass flow rate basis.

As shown in the FIG. 1, the process gas 12 may be further processed.

After suitable cooling, the process gas 12 may be shifted in one or moreshift reactors 310 to form the process gas 14 after shift. Withreference to the FIG. 1, the process gas 12 is shifted in shift reactor310 prior to indirect heat exchange with the second stream 502 in heatexchanger 314. As used herein, the process gas is shifted if a portionor all of the process gas is shifted.

When the process gas 12 is shifted, the method further comprisesintroducing at least a portion of the stream formed from the reformedgas mixture into a shift reactor. Shift reactors, also called water-gasshift reactors, and their operation are well-known in the art. One ormore shift reactors may be employed. Shift reactors comprise a vesselcontaining a catalyst bed through which CO and H₂O flows to form H₂ andCO₂. The one or more shift reactors may be high temperature, mediumtemperature, low temperature and/or isothermal shift reactors. Hightemperature shift reactors may operate at about 350° C. to 450° C. andtypically use a non-noble metal catalyst such as mixture of Fe₃O₄ andCr₂O₃ (i.e. about 55 wt % Fe and 6 % Cr). Low temperature shift reactorsmay operate at about 200° C. to 260° C. and may use a non-noble catalystsuch as Cu—ZnO—Al₂O₃, or Cu—ZnO—Cr₂O₃. Medium temperature shift reactorsoperate in the same temperature range as low temperature shift reactorsand use a similar catalyst. Low temperature shift reactors are used incombination with high temperature shift reactors, whereas mediumtemperature shift reactors may be operated without an upstream hightemperature shift reactor. Medium temperature shift catalyst is designedto withstand a higher temperature rise through the catalyst bed. Some COremains after the water-gas shift reaction and there is therefore CO inthe effluent of the shift reactor.

Shift reactors and suitable shift catalysts are known in the art. Anysuitable shift catalyst may be used. One skilled in the art can readilyselect a suitable shift catalyst.

A by-pass conduit 15 may included to re-route the flow process gas 14around heat exchanger 314. Since the second stream 502 containssuspended and/or dissolved solids, heat exchanger 314 will likelyrequire maintenance. When heat exchanger 314 requires cleaning and/orother maintenance, the process gas 14 by-passes heat exchanger 314 viaby-pass conduit 15. Process gas 14 continues downstream for furtherprocessing while heat exchanger 314 is cleaned or otherwise maintained.This will provide the benefit that the process gas is further processedto produce hydrogen while allowing cleaning of heat exchanger 314.

Heat may be transferred from process gas 14 to process make-up water 170and condensate 171 in heat exchanger 316. The process gas may be furthercooled to condense water contained therein and the condensate 171separated from water-depleted process gas 17 in water separator 323.Condensate 171 may be combined with process make-up water 170 so thatboiler feed water 173 comprises the condensate 171.

The process may further comprise scrubbing the process gas 14 orwater-depleted process gas 17 with a wash stream 118 to form a carbondioxide-depleted process gas 18 and a carbon dioxide-loaded wash stream119. Scrubbing may be done in a so-called gas scrubber 325. Carbondioxide scrubbing is also known in the art as acid gas removal. The washstream 118 may be any scrubbing fluid known in the art, for exampleN-methyl diethanolamine (aMDEA). Other scrubbing fluids associated withother scrubbing methods, for example, RECTISOL®, SELEXOL®, GENOSORB®,and SULFINOL® are known in the art.

The term “depleted” means having a lesser mole % concentration of theindicated component than the original stream from which it was formed.This means that the carbon dioxide-depleted process gas has a lessermole % concentration of carbon dioxide than the process gas which wasintroduced into the scrubber 325. The wash stream, having an affinityfor carbon dioxide will become “loaded” with carbon dioxide. Carbondioxide will become absorbed or otherwise taken in by the wash stream118.

Water may be removed from the process gas 14 prior to the gas scrubber325 via water separator 323 and/or in the gas scrubber 325. Additionalwater may be removed from the carbon dioxide-depleted process gas afterthe scrubber 325. Water removal is conventional and water may be removedby any suitable water removal device known in the art.

CO₂ from the carbon dioxide-loaded wash stream 119 may be sequesteredand/or introduced into the steam-containing stream 550.

The process gas 14, the water-depleted process gas 17 and/or the carbondioxide-depleted process gas 18 may be separated into a hydrogen productgas 19 and a residual gas 30 in separator 330. As discussed above, thefuel 30, 32 may comprise the residual gas 30. The step of separating thevarious process gases may be done by pressure swing adsorption and/ortemperature swing adsorption. Construction and operation of pressureswing adsorbers and temperature swing adsorbers are known in the art.Suitable devices and operating conditions may be selected by one skilledin the art.

Hydrogen product gas 19 may be transferred to a hydrogen pipeline. Thehydrogen pipeline may provide hydrogen to a hydrocarbon upgrader whereheavy hydrocarbons such as bitumen are upgraded by reaction withhydrogen.

The method may optionally comprise operating a gas turbine powergenerator 610 to form electrical power and a gas turbine exhaust 615.Gas turbine exhaust is typically at an elevated temperature and containssufficient oxygen for further combustion. The oxidant gas 103 for thereformer may comprise gas turbine exhaust 615.

In case the optional gas turbine power generator 610 is used, the methodmay further comprise heating a third stream 504 comprising at least oneof the injection make-up water 501 and the recycle water 500 in a heatrecovery steam generator 650. The heat recovery steam generator 650produces even more additional steam 540 for the steam-containing stream550 from the third stream 504. The steam 540 may be produced at a thirdpressure between 1 MPa (absolute) to 10 MPa (absolute) or between 2 MPa(absolute) to 6 MPa (absolute) and a third steam quality less than 100%on a mass flow rate basis. The third pressure may be selected based uponthe reservoir properties and distance between the steam generation siteand the reservoir. Fuel 640 may be introduced into the heat recoverysteam generator. Combustion oxidant 618 for the heat recovery steamgenerator 650 may comprise the gas turbine exhaust 615. The third steamquality may be between 50% and 85%.

Although the present invention has been described as to specificembodiments or examples, it is not limited thereto, but may be changedor modified into any of various other forms without departing from thescope of the invention as defined in the accompanying claims.

We claim:
 1. A reformer comprising: a plurality of catalyst-containing tubes for receiving a reformer feed gas mixture and reacting the reformer feed gas mixture in a reforming reaction, the plurality of catalyst-containing tubes located within a combustion section of the reformer; the combustion section for combusting a fuel with an oxidant gas in a combustion reaction external to the plurality of catalyst-containing tubes; and a heat exchanger section downstream of the combustion section for receiving combustion product gases from the combustion reaction, the heat exchanger section comprising: a first heat exchanger for transferring heat from the combustion product gases to the reformer feed gas mixture; a second heat exchanger downstream of the first heat exchanger with respect to the flow of the combustion product gases for transferring heat from the combustion product gases to recycle water from a production well to produce a steam-containing stream from the recycle water, wherein the second heat exchanger is suitable for mechanical cleaning; and a first exhaust downstream of the second heat exchanger with respect to the flow of the combustion product gases for exhausting the combustion product gases from the heat exchanger section wherein the heat exchanger section further comprises a closable second exhaust downstream of the first heat exchanger with respect to the flow of the combustion product gases and upstream of the second heat exchanger with respect to the flow of the combustion gases. 